Gas turbine efficiency and regulation speed improvements using supplementary air system continuous and storage systems and methods of using the same

ABSTRACT

The present invention discloses a novel apparatus and methods for augmenting the power of a gas turbine engine, improving gas turbine engine operation, and reducing the response time necessary to meet changing demands of a power plant. Improvements in power augmentation and engine operation include additional heated compressed air injection, steam injection, water recovery, exhaust tempering, fuel heating, and stored heated air injection.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation-in-part of U.S. patent applicationSer. No. 14/350,469, which claims priority from PCT/US2013/034748, filedon Mar. 31, 2013, which claims priority of U.S. Provisional PatentApplication Ser. No. 61/686,222 filed on Apr. 2, 2012.

TECHNICAL FIELD

The invention relates generally to gas turbine engine power systems,including supplementing the generating capacity of such gas turbineengines, as well as to energy storage for use in providing additionalelectrical power during periods of peak electrical power demand. Morespecifically, a series of improvements to the supplemental generatingsystem are identified.

BACKGROUND OF THE INVENTION

Currently, marginal energy, or peak energy, is produced mainly by gasturbines, operating either in simple cycle or combined cycleconfigurations. As a result of load demand profile, the gas turbine basesystems are cycled up during periods of high demand and cycled down, orturned off, during periods of low demand. This cycling is typicallydriven by the electrical grid operator under a program called “activegrid control”, or AGC. Unfortunately, because industrial gas turbines,which represent the majority of the installed power generation base,were designed primarily for base load operation, a severe penalty isassociated with the maintenance cost of that particular unit when theyare cycled. For example, a gas turbine that is running base load mightgo through a normal maintenance cycle once every three years, or 24,000hours of operation, at a cost of between two million dollars and threemillion dollars ($2,000,000 to $3,000,000). That same cost could beincurred in one year for a gas turbine that is forced to start up andshut down every day due to the severe penalty associated with themaintenance cost of cycling that particular gas turbine. Also, evenaero-derivative engines, which are designed for quick startingcapability, may still take ten (10) minutes or longer to deliver therequired power when called on. This need to cycle the gas turbine fleetis a major issue, and is becoming more problematic with the increaseduse of intermittent renewable energy sources on the grid.

Currently the gas turbine engines used at power plants can turn down toapproximately 50% of their rated capacity. They do this by closing theinlet guide vanes of the compressor, which reduces the air flow to thegas turbine and in turn reduces fuel flow, as a constant fuel air ratiois desired in the combustion process at all engine operating conditions.The goal of maintaining safe compressor operation and gas turbineexhaust emissions typically limit the level of turn down that can bepractically achieved.

One way to safely lower the operating limit of the compressor in currentgas turbines is by introducing warm air to the inlet of the gas turbine,typically extracted from a mid-stage bleed port on the compressor.Sometimes, this warm air is introduced into the inlet to prevent icingas well. In either case, when this is done, the work that is done to theair by the compressor is sacrificed in the process for the benefit ofbeing able to operate the compressor safely at a lower air flow,yielding the increased turn down capability. Unfortunately, bleeding airfrom the compressor has a further negative impact on the efficiency ofthe overall gas turbine system as the work performed on the air that isbled off is lost. In general, for every 1% of air that is bled off thecompressor for this turn down improvement, approximately 2% of the totalpower output of the gas turbine is lost. Additionally, the combustionsystem also presents a limit to the system.

The combustion system usually limits the amount that the system can beturned down because as less fuel is added, the flame temperaturereduces, increasing the amount of carbon monoxide (“CO”) emissionsproduced. The relationship between flame temperature and CO emissions isexponential with reducing temperature, consequently, as the gas turbinesystem gets near the turn-down limit, the CO emissions spike up, so itis important to a maintain a healthy margin from this limit. Thischaracteristic limits all gas turbine systems to approximately 50% turndown capability, or, for a 100 MW gas turbine, the minimum powerturn-down that can be achieved is about 50%, or 50 MW. As the gasturbine mass flow is turned down, the compressor and turbine efficiencyfalls off as well, causing an increase in heat rate of the machine. Someoperators are faced with this situation every day and as a result, asthe load demand falls, gas turbine plants hit its lower operating limitand the gas turbines have to be turned off, which causes the power plantto incur a tremendous maintenance cost penalty.

Another characteristic of a typical gas turbine is that as the ambienttemperature increases, the power output goes down proportionately due tothe linear effect of the reduced density as the temperature of airincreases. Power output can be down by more than 10% from nameplatepower rating during hot days, which is typically when peaking gasturbines are called on most frequently to deliver power.

Another characteristic of typical gas turbines is that air that iscompressed and heated in the compressor section of the gas turbine isducted to different portions of the gas turbine's turbine section whereit is used to cool various components. This air is typically calledturbine cooling and leakage air (hereinafter “TCLA”) a term that is wellknown in the art with respect to gas turbines. Although heated from thecompression process, TCLA air is still significantly cooler than theturbine temperatures, and thus is effective in cooling those componentsin the turbine downstream of the compressor. Typically 10% to 15% of theair that enters the inlet of the compressor bypasses the combustor andis used for this process. Thus, TCLA is a significant penalty to theperformance of the gas turbine system.

Other power augmentation systems, like inlet chilling for example,provide cooler inlet conditions, resulting in increased air flow throughthe gas turbine compressor, and the gas turbine output increasesproportionately. For example, if inlet chilling reduces the inletconditions on a hot day such that the gas turbine compressor has 5% moreair flow, the output of the gas turbine will also increase by 5%. Asambient temperatures drops, inlet chilling becomes less effective, sincethe air is already cold. Therefore, inlet chilling power increase ismaximized on hot days, and tapers off to zero at approximately 45° F.ambient temperature days.

In power augmentation systems such as the one discussed in U.S. Pat. No.6,305,158 to Nakhamkin (the “'158 patent”), there are three basic modesof operation defined, a normal mode, charging mode, and an air injectionmode, but it is limited by the need for an electrical generator that hasthe capacity to deliver power “exceeding the full rated power” that thegas turbine system can deliver. The fact that this patent has beenissued for more than ten (10) years and yet there are no knownapplications of it at a time of rapidly rising energy costs is proofthat it does not address the market requirements. First of all, it isvery expensive to replace and upgrade the electrical generator so it candeliver power “exceeding the full rated power” that the gas turbinesystem can currently deliver. Also, although the injection option asdisclosed in the '158 patent provides power augmentation, it takes asignificant amount of time to start and get on line to the electricalgrid. This makes application of the '158 patent impractical in certainmarkets like spinning reserve, where the power increase must occur in amatter of seconds, and due to do the need for the large auxiliarycompressor in these types of systems, that takes too long to start.

Another drawback is that the system cannot be implemented on a combinedcycle plant without significant negative impact on fuel consumption andtherefore efficiency. Most of the implementations outlined in the '158patent use a recuperator to heat the air in simple cycle operation,which mitigates the fuel consumption increase issue, however, it addssignificant cost and complexity. The proposed invention outlined belowaddresses both the cost and performance shortfalls of the inventiondisclosed in the '158 patent.

Also, as outlined in a related U.S. Pat. No. 5,934,063 to Nakhamkin (the“'063 patent”), there is a valve structure that “selectively permits oneof the following modes of operation: there is a gas turbine normaloperation mode, a mode where air is delivered from the storage systemand mixed with air in the gas turbine, and then a charging mode”. The'063 patent has also been issued for more than ten (10) years and thereare also no known applications of it anywhere in the world. The reasonfor this is again cost and performance shortfalls, similar to thoserelated to the '158 patent. Although this system can be applied withoutan efficiency penalty on a simple cycle gas turbine, simple cycle gasturbines do not run very often so they typically do not pay off thecapital investment in a timeframe that makes the technology attractiveto power plant operators. Likewise, if this system is applied to acombined cycle gas turbine, there is a significant heat rate penalty,and again the technology does not address the market needs. The proposedinvention outlined below addresses both the cost and performance issuesof the '063 patent.

Gas Turbine (GT) power plants provide a significant amount of power tothe grid and are used for both base load capacity and regulation on thegrid. Because of fluctuating electrical load demand and fluctuations inrenewable energy supply, the GT power plants are required to change loadfrequently. Typically, the grid operator, who is monitoring the demand,supply and frequency of the grid, sends a signal to the gas turbinefleet on a plant-by-plant basis, to supply more or less power to makethe supply meet the demand and hold frequency at 50 or 60 hz. Thissignal is called an Active Grid Control (AGC) signal.

FIG. 9A shows the typical load on the Midwest Iso Grid. As it can beseen in FIG. 9A, there is a minimum load of about 48,000 MegaWatts (MW)required between 2 am and 4 am, and there is an increase in demandduring the morning, typically between 4:00 am and 10:00 am, as peopleand businesses start using more power. Accordingly, an 18,000 MWincrease over 6 hours, or 50 MW per minute ramp rate is needed.According to FIG. 9A, the real time ramp rate can be much higher overshort periods of time. By 10 am, the grid power is increased to about66,000 MW and holds at that level until about 5 pm, then power demanddecreases due, for example, to some businesses closing. However, thereis another peak demand around 8 pm coinciding with when people arrivehome and use more power from home. FIG. 9B is an output versusefficiency chart of a typical gas turbine combined cycle plant. At nightmany plants are shut off or turned down to minimum load due to a drop indemand. A GT's efficiency is at its lowest point at minimum load andgenerally increases as load increases, or about 3%, which for a F-Classgas turbine is about 200 BTU/kWh. This represents $1,600 worth of wastedfuel assuming $4/MMBTU fuel cost over an 8 hour period for a single 2×1combined cycle F-class GT power plant (gas turbine engine and steamturbine coupled to the generator). If all 18,000 MW increase describedabove were from plants as described above (going from minimum load tofull load), it would take seventy-two 2×1 combined cycle (CC) GT plantsto go from 250 MW to 500 MW and represent $115,000 worth of wasted fuelin order to meet increasing load demands. This quantity of 2×1 GT powerplants represents 36,000 MW at full load, or just a little more thanhalf of the total 66,000 MW load based on the fact that about 40% of theinstalled generation in the United States is GT's. For the United Statesgrid described above, the 66,000 MW (66 GW) represents about 16%, or onesixth of the 400 GW total US electrical demand on the grid that issupplied by GTs. Therefore, approximately $700,000 in fuel cost iswasted every day across the United States or $250,000,000 ($250 M) inone year in order to support load fluctuations on the entire grid. Thisis a growing challenge as renewable energy sources are becoming a biggerpart of the generation and their availability can fluctuate as well.

As one skilled in the art understands, as the ramp rate of thegenerating asset is improved, less regulation in total is required. Tosupport this ability to support load fluctuations, some of the gridoperators pay a higher rate for the same capacity if it is able torespond faster to changing demand.

SUMMARY

The current invention, which may be referred to herein as TurboPHASE™,provides several options, depending on specific plant needs, to improvethe efficiency and power output of a plant at low loads, and to reducethe lower limit of power output capability of a gas turbine while at thesame time increasing the upper limit of the power output of the gasturbine, thus increasing the capacity and regulation capability of a newor existing gas turbine system.

One aspect of the present invention relates to methods and systems thatallow running gas turbine systems to provide additional power quicklyduring periods of peak demand.

Another aspect of the present invention relates to an energy storage andretrieval system for obtaining useful work from an existing source of agas turbine power plant.

Yet another aspect of the present invention relates to methods andsystems that allow gas turbine systems to be more efficiently turneddown during periods of lowered demand.

One embodiment of the invention relates to a system comprising at leastone existing gas turbine that comprises one first compressor, at leastone electrical generator, at least one turbine connected to thegenerator and the compressor, a combustor, and a combustion case (whichis the discharge manifold for the compressor) and further comprising asupplemental compressor which is not the same as the first compressor.

An advantage of other preferred embodiments of the present invention isthe ability to increase the turn down capability of the gas turbinesystem during periods of lower demand and improve the efficiency andoutput of the gas turbine system during periods of high demand.

Another advantage of embodiments of the present invention is the abilityto increase the turn down capability of the gas turbine system duringperiods of low demand by using a supplemental compressor driven by afueled engine, operation of which is which is independent of theelectric grid.

Another advantage of embodiments of the present invention is the abilityto increase the turn down capability of the gas turbine system duringperiods of low demand by using a supplemental compressor driven by afueled engine which produces heat that can be added to compressed airflowing to the combustion case, from either the supplemental compressor,an air storage system, or both, or such heat can be added to the steamcycle in a combined cycle power plant.

Another advantage of some embodiments of the present invention is theability to increase output of the gas turbine system during periods ofhigh demand by using a supplemental compressor which is not driven bypower produced by the gas turbine system.

Another advantage of some embodiments of the present invention is theability to increase output of the gas turbine system during periods ofhigh demand by using a supplemental compressor which is driven by steamproduced by the heat recovery steam generator of a combined cycle powerplant.

Another advantage of the present invention is the ability to incorporateselective portions of the embodiments on existing gas turbines toachieve specific plant objectives.

Another advantage of an embodiment of the present invention is theability to inject compressed air into a turbine cooling circuit withoutheating up the air prior to such injection, and because cool cooling aircan achieve the same desired metal temperatures with use of lesscompressed air (as compared to heated compressed air), efficiency isimproved.

Another advantage of another embodiment of the present invention is thatbecause the incremental amount of compressed air can be added at arelatively constant rate over a wide range of ambient temperatures, thepower increase achieved by the gas turbine is also relatively constantover a wide range of ambient temperatures. Additionally, since thesupplemental compressed air is delivered without any significant powerincrease from the gas turbine's compressor, (because the compressed airis from either a separately fueled compressor or an a compressed airstorage system), for every 1% of air injected (by mass flow), a 2% powerincrease results. This is significant because other technologies, suchas inlet chillers, for supplementing power yield closer to a 1% powerincrease for each 1% increase of injected air, therefore, twice as muchpower boost is achieved with the same incremental air flow through theturbine and combustor, resulting in a physically smaller, and lowercost, power supplementing system.

One preferred embodiment of the present invention includes anintercooled compression circuit using a supplemental compressor toproduce compressed air that is stored in one or more high pressure airstorage tanks, wherein the intercooling process heat absorbed from thecompressed air during compression is transferred to the steam cycle of acombined cycle power plant.

Optionally, when integrated with a combined cycle gas turbine plant witha steam cycle, steam from the steam cycle can be used to drive asecondary steam turbine which in turn drives a supplemental compressor.The use of high pressure air storage tanks in conjunction with firingthis air directly in the gas turbine gives the gas turbine the abilityto deliver much more power than could be otherwise produced, because themaximum mass flow of air that is currently delivered by the gas turbinesystem's compressor to the turbine is supplemented with the air from theair tanks. On existing gas turbines, this can increase the output of agas turbine system up to the current generator limit on a hot day, whichcould be as much as an additional 20% power output, while at the sametime increasing the turn down capability by 25-30% more than currentstate of the art.

On new gas turbines, the generator and turbine can be oversized todeliver this additional power at any time, thus increasing the nameplate power rating of the system by 20% at a total system cost increasethat is much lower than 20%, with 25-30% more turn down capability thanthe current state of the art.

Other advantages, features and characteristics of the present invention,as well as the methods of operation and the functions of the relatedelements of the structure and the combination of parts will become moreapparent upon consideration of the following detailed description andappended claims with reference to the accompanying drawings, all ofwhich form a part of this specification.

A gas turbine power augmentation system (TPM) has been developed toincrease the power of a gas turbine by adding air back into the gasturbine cycle with a compression process that is very quick to respondto load changes and is more efficient than the gas turbine itself.

The system of the present invention is powered by a fueled engine, suchas a natural gas reciprocating engine. In one embodiment, both areciprocating engine and gas turbine engine burning natural gas are atthe same site. Fuel input for a gas turbine engine is at a relativelyhigh pressure, typically between 300 and 500 psi and is at a temperatureof approximately 80 deg. F. On the other hand, natural gas input for thereciprocating engine is at approximately 5 psi and a temperature ofapproximately 80 deg. F. One challenge is to maintain a liquid free gaswhile dropping the gas pressure to the reciprocating engine two ordersof magnitude. A conventional approach is to use a heated pressureregulator, which is typically powered with electricity, which nets outpower that could otherwise be output from the plant. An improved way toaccomplish this is described below as part of the present invention.Multiple benefits are realized when this is done, including eliminatingthe electrical heating load as well as reducing the temperature in theintercooler coolant, which improves the efficiency of the intercooledcompression process. By using the intercooler coolant to heat the fuel,an efficiency improvement is gained.

The present invention takes air from the atmosphere, pressurizes the airthrough a separate compressor, and injects the air into the GT engine.This presents a unique opportunity to bleed air from the gas turbineengine prior to starting up the TPM in order to heat up the airinjection lines and TPM system. Combining this preheat cycle with thefact that the air is much dryer than the air going through the gasturbine, because of the intercooled process between stages condenseswater out, yields a system that can inject hot air very quickly.Typically the fueled engines used in the TPM system are used foremergency power so they are designed to start in seconds. Combining thisfast starting capability with the pipe preheat cycle, which reverses theflow in the air injection pipe prior to or in parallel with startup,yields an air injection system that can add significant power to thegrid, up to 20% more power from the gas turbine engine, in a matter ofseconds. This response speed will allow the grid to operate much moreefficiently. Additionally, for plants that have steam injection systems,the same air injection pre-heat system can be used to accelerate thespeed that steam injection can be added and taken away from a gasturbine.

Another efficiency improvement can be made while solving a common partload issue that some gas turbine engines experience. On some gas turbineengines equipped with dry low NOx combustion systems, when the gasturbine engine runs at part load, the exhaust temperature increasesabove allowable temperatures. A common solution to this problem is topump cooler air into the gas turbine engine exhaust to effectivelydilute the temperature to a lower, more acceptable temperature.Presently, this air is bled from the gas turbine compressor discharge,which causes a severe efficiency penalty by reducing the amount of airavailable for combustion and to power the turbine. The TPM system is amuch more efficient system at pumping air than the gas turbine,therefore when the air is pumped into the GT's exhaust, a significantefficiency improvement can be realized because the air is no longer bledfrom the compressor discharge. A further improvement occurs because thetemperature and pressure of the air for exhaust cooling can becontrolled separately from the GT.

Another unique aspect of the present invention is that it can generatewater as a by-product of the compressed air injection process. Becauseof the intercooled compression process, as the air is compressed andthen cooled in the intercoolers, water condenses and is forced out ofthe cooler through a drain by the air pressure. The amount of watergenerated depends on the relative humidity; however, about one gallonper minute of water nominally is generated in a single TPM. This watercan be reintroduced into the compressed air stream that is being sent tothe gas turbine engine in the form of steam. The water can be heated andturned into steam by using the waste heat from the TPM. If desired, anadditional water source can be introduced in the same manner. Typicallywhen a GT is steam injected, the steam is taken from the bottoming cyclesteam cycle, which causes a severe drop in efficiency. By using thewaste heat from the TPM to convert the water to steam, not only is thepower increased from the GT, but, there is no loss in power from thebottoming cycle. If desired, the water collected from the condensateprocess can be stored for periods of peak generation needs, so the extrapower can be delivered when needed. Also, especially at co-generationplants, where the primary focus is generating steam and power for aparticular process, sometimes the steam and power are out of balance andexcess steam is available. Because steam injection start up time is 30to 60 minutes the steam is wasted or used inefficiently. With the TPMreverse flow injection pipe heat up process, the injection pipe, whichwould normally be used for the TPM air injection, can be kept preheatedsuch that the steam can be added much faster. Additionally, installing asteam injection system to capture short periods of inefficiency may notmake economic sense, however, with a TPM air injection system alreadyinstalled, the steam system can be added at very low cost.

Another unique aspect of the present invention is its ability to becoupled with an air storage system. The air storage system augments thepower of a gas turbine engine in a similar way to that described above,however, instead of the air being generated real time, the air iscompressed and stored in a tank. When peak power is desired, the air canbe released from the tank and heated with the waste heat from thepreviously-described system. So where the previously-described systemprovides a continuous power increase, the air storage system provides ashort burst of power, typically 30 minutes. A battery system, whichcould be a conventional battery or a super capacitor, that can be addedto the system and serves several roles. First, it can add an extremelyfast and short duration of power which makes the systems describedherein much more valuable to the electric grid. Second, the battery canbe used to start the previously-described system, since it is typicallystarted with a battery system. Third, it can be used to charge the airtank if desired which can further be used to add load to the gridtemporarily for regulation purposes or to adjust the state of charge ofthe battery to optimize the life or regulation capacity of the combinedsystem.

The advantage of the preferred embodiment of these efficiencyimprovements and response rate improvements is that both new andexisting gas turbine power plants will improve the quality of and thevalue of the power they deliver to the grid.

Additional advantages and features of the present invention will be setforth in part in a description which follows, and in part will becomeapparent to those skilled in the art upon examination of the following,or may be learned from practice of the invention. The instant inventionwill now be described with particular reference to the accompanyingdrawings.

BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS

The present invention is described in detail below with reference to theattached drawing figures, wherein:

FIG. 1 is a schematic drawing of an embodiment of the present inventionhaving a supplemental energy system with a recuperated engine drivingthe supplemental compressor.

FIG. 2 is a schematic drawing of an embodiment of the present inventionhaving a supplemental energy system with a recuperated engine drivingthe supplemental compressor and energy storage.

FIG. 3 is a schematic drawing of an embodiment of the present inventionincorporating a continuous power augmentation system.

FIG. 4 is a schematic drawing of an embodiment of the present inventionin which an auxiliary steam turbine is drives the supplementalcompressor.

FIG. 5 is a schematic drawing of an embodiment of the present inventionin which includes an auxiliary steam turbine driving the supplementalcompressor and energy storage.

FIG. 6 is a schematic drawing of an embodiment of the present inventioninstalled in conjunction with two gas turbines and a steam turbine.

FIG. 7 is a schematic drawing of an embodiment of the present inventioninstalled in conjunction with one gas turbine and a steam turbine.

FIG. 8 is a schematic drawing of an embodiment of the present inventioninstalled in conjunction with one gas turbine.

FIG. 9A is a schematic drawing of the typical daily load pattern thatexists on an electric grid.

FIG. 9B is a chart depicting output and efficiency versus time of atypical 2×1 F-Class combined cycle gas turbine power plant.

FIG. 10 is a schematic drawing of an embodiment of the present inventionhaving a system delivering power augmentation air to the gas turbineengine while the natural gas fuel supply is cooling the coolant to thesystem.

FIG. 11 is a schematic drawing of the cooling system in accordance withan embodiment of the present invention.

FIG. 12 is a schematic drawing of an embodiment of the present inventioncapable of delivering power augmentation air to the gas turbine engineand using power augmentation air to cool the exhaust of the gas turbineengine.

FIG. 13 is a schematic drawing of an embodiment of the present inventiondelivering power augmentation air to the gas turbine engine while thewater condensed in the compression process is reintroduced as steaminjection power augmentation to the gas turbine engine.

FIG. 14 is a schematic drawing of an embodiment of the present inventionhaving a system for delivering power augmentation air to the gas turbineengine, and a storage system delivering interim power to the same gasturbine engine.

FIG. 15A is a schematic drawing of the typical daily load pattern thatexists on an electric grid in which the present invention operates.

FIG. 15B is a chart depicting output and efficiency versus time for agas turbine power plant in accordance with an embodiment of the presentinvention.

DETAILED DESCRIPTION

The components of one embodiment of the present invention are shown inFIG. 1 as they are used with an existing gas turbine system 1. Theexisting gas turbine system 1, which compresses ambient air 2, includesa compressor 10, combustor 12, combustion case 14, turbine 16 andgenerator 18. A fueled engine 20 is used to drive a multistageintercooled supplemental compressor 22 which compresses ambient air 24and discharges compressed air 26. As used herein, the term “fueledengine” means a reciprocating internal combustion engine, a gas turbine(in addition to the gas turbine in the existing gas turbine system 1, ora similar machine that converts fuel into energy through an exothermicreaction such as combustion (e.g., gasoline, diesel, natural gas, orbiofuel and similar fuel). The fueled engine draws in ambient air 42 andas a result of the combustion process, produces hot exhaust gas 32. Asthose skilled in the art will readily appreciate, as air in thesupplemental compressor 22 passes from one compressor stage to the next,the air is intercooled by use of an intercooler heat exchanger 28, suchas a cooling tower, to reduce the work required to compress the air atthe subsequent compressor stage. As used herein, the term “intercoolerheat exchanger” means a heat exchanger that receives compressed air froman upstream stage of a compressor, and cools that air before deliveringit to another compression stage downstream of the upstream compressorstage. Use of the intercooler heat exchanger 28 increases the efficiencyof the supplemental compressor 22, which makes it more efficient thanthe compressor 10 of the existing gas turbine system 1. As those skilledin the art will readily appreciate, although referred to herein as an“intercooler”, the intercooler heat exchanger 28 actually includes anintercooler and an after-cooler as described in greater detail below.

This embodiment further includes a recuperator 30, which is a heatexchanger that receives the exhaust gas 32 from the fueled engine 20 andthe compressed air 26 from the supplemental compressor 22. Flow ofcompressed air from the supplemental compressor 22 to the recuperator 30is controlled by the recuperator flow control valve 44. Within therecuperator 30, the hot exhaust gas 32 heats the compressed air 26 andthen exits the recuperator 30 as substantially cooler exhaust gas 34. Atthe same time in the recuperator 30, the compressed air 26 absorbs heatfrom the exhaust gas 32 and then exits the recuperator 30 assubstantially hotter compressed air 36 than when it entered therecuperator 30. The substantially hotter compressed air 36 is thendischarged from the recuperator 30 into the combustion case 14 of thegas turbine system 1 where it becomes an addition to the mass flowthrough the turbine 16.

The cooler exhaust gas 34 is then discharged to atmosphere. A selectivecatalytic reduction (“SCR”) device (not shown) of the type known in theart, can be inserted before, in the middle of, or after the recuperator30 to achieve the most desirable condition for the SCR function.Alternately, after the SCR device, the cooler exhaust gas 34 can beinjected into the exhaust gas 38 of the turbine 16 as shown in FIG. 1,and then the mixed flow exhaust 38 will either be discharged to theatmosphere (in the case for the simple cycle gas turbine) or directed tothe heat recovery steam generator (“HRSG”) of a steam turbine of thetype known in the art (not shown) in combined cycle power plants. If themixed flow exhaust 38 is to be discharged into the HRSG, the means usedmust ensure that the exhaust gas 38 flow from the turbine 16 into theHRSG and the SCR device is not disrupted. On “F-Class” engines, such asthe General Electric Frame 9FA industrial gas turbine, there are largecompressor bleed lines that, for starting purposes, bypass air aroundthe turbine section and dump air into the exhaust plenum of the turbine16. These bleed lines are not in use when the gas turbine system 1 isloaded, and therefore are a good place to discharge the cooler exhaustgas 34 after it exits the recuperator 30, since these compressor bleedlines are already designed to minimize the impact on the HRSG and SCRdevice. By injecting the exhaust 32 from the fueled engine 20 into toexhaust 38 of the gas turbine system 1, the SCR of the gas turbinesystem 1 may be used to clean the exhaust 32, thus eliminating anexpensive system on the fueled engine 20.

It turns out that gasoline, diesel, natural gas, or biofuel and similarreciprocating engines are not sensitive to back pressure, so putting therecuperator 30, on the fueled engine 20 does not cause a measurableeffect on the performance of the fueled engine 20. This is significantbecause other heat recovery systems, such as the HRSGs used in theexhaust of a typical gas turbine power plants, create a significantpower loss all of the time, independent of whether a power augmentationsystem is in use or not.

The power from the fueled engine 20 is used to drive the intercooledcompressor 22. If the installation does include a HS G and a steamturbine, the auxiliary heat from the engine jacket, oil cooler andturbocharger on the fueled engine 20 can be transferred into the steamcycle of the steam turbine via the HSRG (typically the low pressure andtemperature condensate line) Likewise, heat removed by the intercoolerheat exchanger 28 from the air as it is compressed in the multistagesupplemental compressor 22 can be transferred into the steam cycle in asimilar manner, prior to the compressed air being cooled by the coolingtower, to lower the temperature of the compressed air to the desiredtemperature prior to entering the subsequent compression stage of thesupplemental compressor 22. If an auxiliary gas turbine is used as thefueled engine 20 instead of a reciprocating engine, lower emission rateswill be achievable, which will allow emission permitting even in thestrictest environmental areas. Also, if the auxiliary gas turbine isused as the fueled engine 20, the exhaust gas from the auxiliary gasturbine can be piped directly to the exhaust bleed pipes of the existinggas turbine system 1 described above, thus avoiding the cost andmaintenance of an additional SCR device.

When peaking with this system, the gas turbine system 1 will most likelybe down in power output and flow (assuming that the peaking is needed inthe summer when higher ambient air temperatures reduce total mass flowthrough the gas turbine system 1 which in turn reduces power output ofthe gas turbine system 1 as a whole, and the supplemental compressor 22will just bring the air mass flow through the gas turbine system 1 backup to where the flow would have been on a cooler day (i.e. a day onwhich the full rated power of the gas turbine system 1 could beachieved).

FIG. 2 shows the embodiment of FIG. 1 with the addition of compressedair storage. The compressed air storage system includes an air storagetank 50, a hydraulic fluid tank 52, and a pump 54 for transferringhydraulic fluid, such as water, between the hydraulic fluid tank 52 andthe air storage tank 50. According to preferred embodiments, duringperiods when increased power delivery is needed, the air exit valve 46opens, the air bypass valve 48 opens, the air inlet valve 56 closes, andthe supplemental compressor 22 is operated, driven by the fueled engine20. As one skilled in the art will readily appreciate, if compressed airis to be stored for later use, it will likely need to be stored at ahigher pressure, thus, the supplemental compressor 22 would preferablyhave additional stages of compression, as compared to the supplementalcompressor 22 of the embodiment shown in FIG. 1. These additional stagesmay be driven by the fueled engine 20 all the time, or may be capable ofbeing driven intermittently by installing a clutch type mechanism thatonly engages the additional stages when the fueled engine 20 is operatedto store compressed air in the air storage tank 50 (where the desiredstorage pressure is substantially higher to minimize the required volumeof the air storage tank 50). Alternatively, the additional stages may bedecoupled from the fueled engine 20 and driven by a separately fueledengine (not shown) or other means, such as an electric motor.

The compressed air 26 flowing from the supplemental compressor 22 isforced to flow to the mixer 58 as opposed to towards the intercoolerheat exchanger 28 because the air inlet valve 56, which controls airflow exiting the intercooler heat exchanger 28, is closed. Thecompressed air 26 flowing from the outlet of the supplemental compressor22 is mixed in the mixer 58 with the compressed air exiting the airstorage tank 50 and introduced to the recuperator 30 where it absorbsheat from the exhaust gas of the fueled engine 20 before beingintroduced into the combustion case 14 using the process describedbelow. As those skilled in the art will readily appreciate, for thermalefficiency purposes, the recuperator 30 would ideally be a counter-flowheat exchanger, since that would allow the maximum amount of heat fromthe exhaust 32 to be transferred to the compressed air exiting the airstorage tank 50. Alternately, if the recuperator 30 is made up of one ormore cross-flow heat exchangers, it can have a first stage, which is afirst cross-flow heat exchanger, followed by a second stage, which is asecond cross-flow heat exchanger. In this configuration, where theexhaust 32 first enters the first stage of the recuperator, is partiallycooled, then flows to the second stage of the recuperator. At the sametime, the compressed air exiting the air storage tank 50 first entersthe second stage of the recuperator 30, where additional heat isextracted from the partially cooled exhaust 32, thereby “pre-heating”the compressed air. The compressed air then flows to the first stage ofthe recuperator 30 where it is heated by exhaust 32 that has not yetbeen partially cooled, prior to flowing to the mixer 58 to join the airflowing from the supplemental compressor 22. In this case, the “twostage” recuperator acts more like a counter-flow heat exchanger,yielding higher thermal efficiency in the heating of the compressed air.

As those skilled in the art will readily appreciate, since the air beingcompressed in the supplemental compressor 22 is bypassing theintercooler heat exchanger 28 due to the bypass valve 48 being open, thecompressed air exiting the supplemental compressor 22 retains some ofthe heat of compression, and when mixed with the compressed air flowingfrom the air storage tank 50, will increase the temperature of the mixedair so that when the mixed air enters the recuperator 30, it is hotterthan it would be if only compressed air from the air storage tank 50 wasbeing fed into the recuperator 30. Likewise, if the air exiting the airstorage tank 50 is first preheated in a “second stage” of therecuperator as described above prior to entering the mixer 58, an evenhotter mixture of compressed air will result, which may be desirableunder some conditions.

As the combustion turbine system 1 continues to be operated in thismanner, the pressure of the compressed air in the air storage tank 50decreases. If the pressure of the compressed air in the air storage tank50 reaches the pressure of the air in the combustion case 14, compressedair will stop flowing from the air storage tank 50 into the gas turbinesystem 1. To prevent this from happening, as the pressure of thecompressed air in the air storage tank 50 approaches the pressure of theair in the combustion case 14, the fluid control valve 60 remainsclosed, and the hydraulic pump 54 begins pumping a fluid, such as water,from the hydraulic fluid tank 52 into the air storage tank 50 at apressure high enough to drive the compressed air therein out of the airstorage tank 50, thus allowing essentially all of the compressed air inthe air storage tank to be delivered to the combustion case 14.

As those skilled in the art will readily appreciate, if additionalcompressor stages, or high pressure compressor stages, are addedseparate from the supplemental compressor 22 driven by the fueled engine20, then, if desired, air from the gas turbine combustion case 14 can bebled and allowed to flow in reverse of the substantially hottercompressed air 36 as bleed air from the gas turbine combustion case 14and take the place of air from the separately fueled engine 20 drivensupplemental compressor 22. In this case, the bleed air could be cooledin the intercooler heat exchanger 28, or a cooling tower, and thendelivered to the inlet of the high pressure stages of the supplementalcompressor 22. This may be especially desirable if low turn downcapability is desired, as the bleed air results in additional gasturbine power loss, and the drive system for the high pressure stages ofthe supplemental compressor 22 can driven by an electric motor,consuming electrical power generated by the gas turbine system 1, whichalso results in additional gas turbine power loss. As those skilled inthe art will readily appreciate, this is not an operating mode thatwould be desirable during periods when supplemental power productionfrom the gas turbine system is desired.

According to preferred embodiments, independent of whether or not thehydraulic system is used, when the air stops flowing from the airstorage tank 50, the supplemental compressor 22 can continue to run anddeliver power augmentation to the gas turbine system 1. According toother preferred embodiments, such as the one shown in FIG. 1, thesupplemental compressor 22 is started and run without use of an airstorage tank 50. Preferably, an intercooler heat exchanger 28 is used tocool air from a low pressure stage to a high pressure stage in thesupplemental compressor 22 that compresses ambient air 24 through amultistage compressor 22.

The air inlet valve 56, the air outlet valve 46, the bypass valve 48,and the supplemental flow control valve 44, are operated to obtain thedesired operating conditions of the gas turbine system 1. For example,if it is desired to charge the air storage tank 50 with compressed air,the air outlet valve 46, the bypass valve 48 and the supplemental flowcontrol valve 44 are closed, the air inlet valve 56 is opened and thefueled engine 20 is used to drive the supplemental compressor 22. As airis compressed in the supplemental compressor 22, it is cooled by theintercooler heat exchanger 28 because the bypass valve 48 is closed,forcing the compressed air to flow through the intercooler heatexchanger 28. Air exiting the supplemental compressor 22 then flowsthrough the air inlet valve 56 and into the air storage tank 50.Likewise, if it is desired to discharge compressed air from the airstorage tank 50 and into the combustion case 14 the air outlet valve 46,the bypass valve 48 and the supplemental flow control valve 44 areopened, and the air inlet valve 56 can be closed, and the fueled engine20 can be used to drive the supplemental compressor 22.

As air is compressed in the supplemental compressor 22, it heats up dueto the heat of compression, and it is not cooled in the intercooler heatexchanger because bypass valve 48 is open, thereby bypassing theintercooler heat exchanger. Compressed air from the air storage tank 50then flows through the mixer 58 where it is mixed with hot air from thesupplemental compressor 22 and then flows to the recuperator 30 where itabsorbs heat transferred to the recuperator 30 from the exhaust gas 32of the fueled engine 20 and then flows on to the combustion case 14. Inthe event that all of the airflow from the supplemental compressor 22 isnot needed by the gas turbine system 1, this embodiment can be operatedin a hybrid mode where the some of the air flowing from the supplementalcompressor 22 flows to the mixer 58 and some of the air flow from thesupplemental compressor 22 flows through the intercooler heat exchanger28 and then through the air inlet valve 56 and into the air storage tank50.

As those skilled in the art will readily appreciate, the preheated airmixture could be introduced into the combustion turbine at otherlocations, depending on the desired goal. For example, the preheated airmixture could be introduced into the turbine 16 to cool componentstherein, thereby reducing or eliminating the need to extract bleed airfrom the compressor to cool these components. Of course, if this werethe intended use of the preheated air mixture, the mixture's desiredtemperature would be lower, and the mixture ratio in the mixer 58 wouldneed to be changed accordingly, with consideration as to how much heat,if any, is to be added to the preheated air mixture by the recuperator30 prior to introducing the compressed air mixture into the coolingcircuit(s) of the turbine 16. Note that for this intended use, thepreheated air mixture could be introduced into the turbine 16 at thesame temperature at which the cooling air from the compressor 10 istypically introduced into the TCLA system of the turbine 16, or at acooler temperature to enhance overall combustion turbine efficiency(since less TCLA cooling air would be required to cool the turbinecomponents).

It is to be understood that when the air storage tank 50 has hydraulicfluid in it prior to the beginning of a charging cycle to add compressedair to the air storage tank 50, the fluid control valve 60 is opened sothat as compressed air flows into the air storage tank 50 it drives thehydraulic fluid therein out of the air storage tank 50, through thefluid control valve 60, and back into the hydraulic fluid tank 52. Bycontrolling the pressure and temperature of the air entering the turbinesystem 1, the gas turbine system's turbine 16 can be operated atincreased power because the mass flow of the gas turbine system 1 iseffectively increased, which among other things, allows for increasedfuel flow into the gas turbine's combustor 12. This increase in fuelflow is similar to the increase in fuel flow associated with cold dayoperation of the gas turbine system 1 where an increased mass flowthrough the entire gas turbine system 1 occurs because the ambient airdensity is greater than it is on a warmer (normal) day.

During periods of higher energy demand, the air flowing from the airstorage tank 50 and supplemental compressor 22 may be introduced to thegas turbine system 1 in a manner that offsets the need to bleed coolingair from the compressor 10, thereby allowing more of the air compressedin the compressor 10 to flow through the combustor 12 and on to theturbine 16, thereby increasing the net available power of the gasturbine system 1. The output of the gas turbine 16 is very proportionalto the mass flow rate through the gas turbine system 1, and the systemdescribed above, as compared to the prior art patents, delivers higherflow rate augmentation to the gas turbine 16 with the same air storagevolume and the same supplemental compressor size, when the two are usedsimultaneously to provide compressed air, resulting in a hybrid systemthat costs much less than the price of prior art systems, whileproviding comparable levels of power augmentation.

The supplemental compressor 22 increases the pressure of the ambient air24 through at least one stage of compression, which is then cooled inthe intercooler heat exchanger 28, further compressed in a subsequentstage of the supplemental compressor 22, and then after-cooled in theintercooler heat exchanger 28 (where the compressed air exiting the laststage of the supplemental compressor 22 is then after-cooled in the sameintercooler heat exchanger 28), and then the cooled, compressed, highpressure air is delivered to the air storage tank 50 via the open airinlet valve 56 and the inlet manifold 62, and is stored in the airstorage tank 50.

As the pressurized air flowing through the intercooler heat exchanger 28is cooled, the heat transferred therefrom can be used to heat water inthe H SG to improve the efficiency of the steam turbine. An alternatemethod to cool the compressed air in the intercooler heat exchanger 28is to use relatively cool water from the steam cycle (not shown) on acombined cycle plant. In this configuration, the water would flow intothe intercooler heat exchanger 28 and pick up the heat that is extractedfrom the compressed air from the supplemental compressor 22, and thethen warmer water would exit the intercooler heat exchanger 28 and flowback to the steam cycle. With this configuration, heat is capturedduring both the storage cycle described in this paragraph, and the poweraugmentation cycle described below.

According to preferred embodiments, the air storage tank 50 isabove-ground, preferably on a barge, skid, trailer or other mobileplatform and is adapted or configured to be easily installed andtransported. The additional components, excluding the gas turbine system1, should add less than 20,000 square feet, preferably less than 15,000square feet, and most preferably less than 10,000 square feet to theoverall footprint of the power plant. A continuous augmentation systemof the present invention takes up 1% of the footprint of a combinedcycle plant and delivers from three to five times the power per squarefoot as compared to the rest of the plant, thus it is very spaceefficient, while a continuous augmentation system of the presentinvention with storage system takes up 5% of the footprint of thecombined cycle plant and delivers from one to two times the power persquare foot of the power plant.

FIG. 3 shows another embodiment of the present invention in which anauxiliary gas turbine 64 is used to provide supplemental air flow attimes when additional power output from the gas turbine system 1 isneeded. The auxiliary gas turbine 64 includes a supplemental compressorsection 66 and a supplemental turbine section 68. In this embodiment,the auxiliary gas turbine is designed so that substantially all of thepower produced by the supplemental turbine section 68 is used to drivethe supplemental compressor section 66. As used herein the term“substantially all” means that more than 90% of the power produced bythe supplemental turbine section 68 is used to drive the supplementalcompressor 66, because major accessories, such as the electric generatorused with the gas turbine system 1, are not drawing power from theauxiliary gas turbine section 68. Manufacturers of small gas turbines,such as Solar Turbines Inc., have the capability to mix and matchcompressors and combustors/turbines because they build their systemswith multiple bearings to support the supplemental compressor section 66and the supplemental turbine section 68. A specialized turbine, with anoversized gas turbine compressor 66 and with a regular sizedturbine/combustion system 68 is used to provide additional supplementalairflow to the gas turbine system 1, and the excess compressed air 70output from the oversized compressor 66, which is in excess of what isneeded to run the turbine/combustion system 68, flows through thecombustion case flow control valve 74, when it is in the open position,and is discharged into the combustion case 14 of the gas turbine system1 to increase the total mass flow through the turbine 16 of the gasturbine system 1, and therefore increases the total power output by thegas turbine system 1. For example, a 50 lb/sec combustor/turbine section68 that would normally be rated for 4 MW, may actually be generating 8MW, but the compressor is drawing 4 MW, so the net output from thegenerator is 4 MW. If such a turbine were coupled with a 100 lb/seccompressor on it, but only 50 lbs/sec were fed to the combustor/turbinesection 68, the other 50 lb/sec could be fed to the combustion case ofthe gas turbine system 1. The exhaust 72 of the 50 lb/seccombustor/turbine section 68 could be injected into the exhaust 38 ofthe main turbine 16 similar to the manner described in the embodimentshown in FIG. 1, and jointly sent to the SCR. Optionally, the exhaustcan be separately treated, if required.

Obviously, the pressure from the 100 lb/sec compressor 66 has to besufficient to drive the compressed air output therefrom into thecombustion case 14. Fortunately, many of the smaller gas turbine enginesare based on derivatives of aircraft engines and have much higherpressure ratios than the large industrial gas turbines used at mostpower plants. As shown in FIG. 3, this embodiment of the presentinvention does not include the recuperator 30, the intercooledcompressor 22, or the intercooler heat exchanger 28 shown in FIGS. 1 and2. Of course, the embodiment shown in FIG. 3 does not provide theefficiency improvement of the intercooled embodiments shown in FIGS. 1and 2, however the initial cost of the embodiment shown in FIG. 3 issubstantially less, which may make it an attractive option to operatorsof power plants that typically provide power in times of peak demand,and that therefore are not run much and are less sensitive to fuelefficiency. When the auxiliary gas turbine 64 is not running, thecombustion case flow control valve 74 is closed.

The embodiment shown in FIG. 4 shows another way to incorporate asupplemental compressor 22 into the gas turbine system 1. In somesituations, the gas turbine augmentation of the present invention with(i) the additional mass flow to the HRSG, and/or (ii) the additionalheat from the intercooler heat exchanger 28 and fueled engine 20 (ascompared to a gas turbine system 1 that does not incorporate the presentinvention), may be too much for the steam turbine and/or the steamturbine generator to handle if all of the additional heat flows to thesteam turbine generator (especially if the power plant has duct burnersto replace the missing exhaust energy on hot days). In this case, theadditional steam generated as a result of adding the heat of compressiongenerated by the supplemental compressor 22 can be extracted from thesteam cycle HRSG. As it happens, when compressed air augmentation isadded to the gas turbine system 1, the heat energy extracted from theintercooler heat exchanger 28 generates about the same amount of energythat it takes to drive the supplemental compressor 22. In other words,if you had a steam turbine that generated 100 MW normally and 108 MWwhen the supplemental compressor 22 was injecting compressed air intothe gas turbine system 1, the extra 8 MW is approximately equal to thepower requirement to drive the intercooled supplemental compressor 22.Therefore, if some of the steam is extracted from the steam cycle of thepower plant, and the steam turbine is kept at 100 MW, a small auxiliarysteam turbine 76 can be used to drive the intercooled supplementalcompressor 22, and there would be no additional source of emissions atthe power plant.

In FIG. 4, an auxiliary steam turbine 76 drives the intercooledsupplemental compressor 22 and the steam 78 that is used to drive thesteam engine 76, which comes from the HRSG (not shown) of the powerplant, is the extra steam produced from the heat, being added to theHRSG, which was extracted by the intercooler heat exchanger 22 duringcompression of air in the supplemental compressor 22. The exhaust 80 ofthe steam engine 76 is returned to the HRSG where it is used to producemore steam. This embodiment of the present invention results in asignificant efficiency improvement because the compression process ofthe supplemental compressor 22 is much more efficient than thecompressor 10 of the gas turbine system 1. In this situation, the poweraugmentation level will, of course, be reduced as the steam turbine willnot be putting out additional MW, however there will be no other sourceof emissions/fuel burn.

FIG. 5 shows the embodiment of FIG. 4 with the addition of compressedair storage. This implementation of compressed air energy storage issimilar to that described with respect to FIG. 2, as is the operationthereof. As those skilled in the art will readily appreciate, the poweraugmentation level of the embodiment shown in FIG. 5 is less than theembodiment shown in FIG. 2, since the steam turbine will not be puttingout additional MW, however there will be no other source ofemissions/fuel burn.

FIGS. 6-8 show various implementations of the embodiment shown in FIG.1, referred to as the “TurboPHASE system”. TurboPHASE, which is asupplemental power system for gas turbine systems, is a modular,packaged “turbocharger” that can be added to most, if not all, gasturbines, and can add up to 20% more output to existing simple cycle andcombined cycle plants, while improving efficiency (i.e. “heat rate”) byup to 7%. The TurboPHASE system is compatible with all types of inletchilling or fogging systems, and when properly implemented, will leaveemissions rates (e.g. ppm of NOx, CO, etc.) unchanged, while thespecific emissions rates should improve as the result of improvement inheat rate. Since only clean air, at the appropriate temperature, isinjected into the turbine, the TurboPHASE system has no negative effecton gas turbine maintenance requirements. Due to the factory-assembled &tested modules that make up the TurboPHASE system, installation at anexisting power plant is quick, requiring only a few days of the gasturbine system being down for outage to complete connections and toperform commissioning.

FIG. 6 shows an implementation of the embodiment of the presentinvention shown in FIG. 1 in conjunction with two 135 MW GeneralElectric Frame 9E industrial gas turbines 82, 84 in a combined cycleconfiguration with a 135 MW steam turbine 86 (“ST”). The results of thisimplementation are shown below in Table 1.

TABLE 1 (7.0% additional Flow added to 2x1 9E combined cycle on a 59 F.day (+71 lbs/sec per GT)) Existing plant With TurboPHASE ™ Compressorpressure ratio 12.7 13.6 Compressor discharge temperature 673 F. 760 F.Compressor discharge pressure 185 psi 197 psi Turbine Firing temperature2035 F. 2035 F. Turbine exhaust temperature 1000 F. 981 F. (−19 F.) 9EGT Output(MW each) 135 MW (base load each) +23 MW (+17% output)Increased flow N/A +20.7 Increase PR turbine output (delta) N/A +5.6Increase PR compressor load (delta) N/A −3.3 ST output (MW) 135 MW (baseload) +16 MW (+12%) Increased flow N/A +9.4 Cooler Exhaust temp N/A −2.9Jacket heat and IC heat put into ST N/A +9.9 9E Plant Output SC (MW) 135MW (base load) 158 MW (+23 MW or +17%) 9E Plant Output CC (MW) 405 MW(base load) 467 MW (+62 MW or +15%) Base load Fuel Burn per GT 1397MMBTU/hr 1514 MMBTU/hr Fuelburn of aux engine delivering 71 lbs/sec N/A96 MMBTU/hr (740 Gal/hr ~15,000 HP) Total additional fuel burn of GT N/A11 MMBTU/hr (+1%) Increase flow N/A 98 MMBTU/hr (+7%) IncreasedPR/higher CDT/mixed temp N/A −77 MMBTU/hr Total Plant Fuel Burn CC 2974MMBTU/hr 3028 MMBTU/hr Heat rate SC 10850 BTU/kWh 5582 BTU/kWh (−767BTU/kWh or −7%) Heat rate CC 6900 BTU/kWh 6483 BTU/kWh (−416 BTU/kWh or−6%)

As is clear from Table 1, the implementation increased power output fromeach of the gas turbines by 23 MW, and increased power output from thesteam turbine by 6 MW, for a total of 52 MW (2×23 MW+6 MW=52 MW). TheTurboPHASE system increases air flow to the gas turbines by 7%, isoperable at any ambient temperature, and yields a 4% heat rateimprovement. In doing so, the pressure ratio (“PR”) at the gas turbineoutlet of each gas turbine increased by 5.6, while the PR of thecompressor load exhibited a 3.3 decrease. The total fuel consumptionrate for the combined cycle (“CC”) plant increased by 54 MMBTU/hr whilethe heat rate for the CC plant decreased by 416 BTU kWh. Forinformational purposes, Table 1 also shows that if the implementationhad been on a simple cycle (“SC”) plant, the increased power output fromeach of the gas turbines by would have totaled 46 MW, while the heatrate would have decreased by 767 BTU/kWh. As an option, the intercoolerheat exchanger can be eliminated and the supplemental compressor heatand engine heat added to the steam turbine cycle, which increases SToutput from +6 MW to +16 MW (62 MW total) and improves heat rate by 6%.

FIG. 7 shows an implementation of the embodiment shown in FIG. 1 on a CCplant comprising one General Electric Frame 9FA industrial gas turbine82 and one 138 MW steam turbine. In this implementation, power output bythe 9FA industrial gas turbine 82 is increased by 42 MW from 260 MW, andpower output by the steam turbine 88 is increased by 8 MW, for a totalpower output increase of 50 MW, along with a heat rate improvement of0.25%. As an option, the intercooler heat exchanger 28 can be eliminatedand the heat of compression of the supplemental compressor 22 and theheat from the exhaust 32 of the fueled engine can be added to the H SGin the steam cycle, which increases ST output from +8 MW to +14 MW (56MW total) and improves heat rate to 1.8%.

FIG. 8 shows an implementation of the embodiment shown in FIG. 1 on a SCplant comprising one General Electric Frame 9B (or 9E) industrial gasturbine 90. In this implementation, power output by the 9B is increasedby 23 MW from 135 MW, along with a heat rate improvement of 7%.

Implementation of the embodiments of the present invention preferablyprovide the following benefits: (i) Installation is quick and simple,with no major electric tie-in required; (ii) No change in gas turbinefiring temperature, so gas turbine maintenance costs are unchanged;(iii) It uses existing ports on gas turbine system's combustion case toinject air; (iv) High efficiency, recuperated and internal combustionengine-driven inter-cooled supplemental compressor improves both SC andCC heat rates; (v) It is compatible with water injection, fogging, inletchilling, steam injection, and duct burners; (vi) Air is injected intogas turbine combustion case at compatible temperatures and pressures;(vii) The internal combustion, reciprocating, fueled engine can burnnatural gas, low BTU biofuel or diesel (also available with small steamturbine driver and small gas turbine driver for the fueled engine); and(viii) Energy storage option also available: approximately 2 times theprice and 2 times the efficiency improvement.

Referring now to FIG. 10, one embodiment of the present inventionrelates to improving the efficiency of the TPM compression process bytransferring heat from the TPM coolant to the fuel entering the TPM. Atypical gas turbine 1 has an axial compressor 10, a combustion system12, a compressor discharge plenum 14, a turbine 16 and a generator 18which is compressing air 20 and adding fuel 24 to react and generate hotgasses 22 passing through the turbine 16 and going out the exhaust ofthe gas turbine.

The present invention comprises a fueled engine 151 driving aintercooled compressor 116 which takes ambient air 115, compresses air115, and yields a relatively cool compressed air 117 exiting theintercooled compressor 116. The compressed air 117 is later heated in arecuperator 171, resulting in heated compressed air 141, which is andthen injected into the gas turbine engine 1 when the injection controlvalve 142 is open, where the heat transferred to the air in recuperator171 comes from the exhaust 152 of a fueled engine 151, which is drivingthe compressor 116. Warm exhaust 153 exits the recuperator 171 aftersome of the energy is transferred to the compressed air 117.

The compressor intercooler 205 has coolant 202 entering the coolerswhich is typically water or water with an additive to keep it fromfreezing. The coolant temperature is a main component to the efficiencyof the intercooled compressor 116. The colder the coolant 202, the moreefficient the compression process. A fuel regulator 125 is used to dropthe pressure of the pipeline gas 126 several orders of magnitude to nearambient pressure gas 127 which is required for natural gas reciprocatingengines, such as the fueled engine 151. When the pressure in the gas isdropped, the temperature is reduced significantly, typically about 10 Ffor every 100 psi pressure drop. In one aspect of this invention, thecoolant 162 for the intercooled compression process 162 is used to heatthe natural gas 127 in a fuel heater 181 positioned downstream of thefuel regulator 125. This process also reduces the temperature of coolant202 entering the intercoolers 205 which results in another efficiencyimprovement to the system. In prior art systems, an electric heater isprovided to heat the fuel. However, electric heaters reduce overallefficiency since they consume power in order to operate.

Another aspect of the invention relates to the through coolingarrangement of the intercooled compressor. Typically reciprocatingengines are cooled with air coolers (radiators), however, since theintercooled compressor requires water coolant, a complete once throughpackage cooling system is much more cost effective and allows foroptimized temperature control in the different engine coolant andcompressor coolant systems. Referring to FIG. 11, an intercooledcompressor 205, gearbox 218, and fueled engine 212 are shown along witha once through coolant system 201. Coolant 202 enters the system 201 andis split four ways, three main paths 204 pass through each of theintercoolers 205 and path 208 for cooler 209 of gearbox 218. It isunderstood that the number of main paths 204 are not limited to threebut instead correspond to the quantity of intercoolers 205 present. Thecoolant exiting 206 from the intercoolers 205 is then joined together ina manifold 207, which in turn joins together with the coolant 210exiting the gearbox cooler 209 to form the engine coolant 211 forcooling the fueled engine 212. The engine coolant 211 feeds a manifold213 that has three separate paths: a high temperature (HT) cooler 214,which typically cools the engine jacket of the fueled engine 212 andacts as the first of two stages of cooling for the turbochargedreciprocating engine air; the low temperature (LT) cooler 216, which isthe second stage of cooling on the turbocharged reciprocating engineair, and a bypass 215. Each of these circuits 214, 215, and 216 providescritical cooling function which must be closely controlled to provideoptimum engine performance and emissions. After the coolant passesthrough these three engine related coolers 214 and 216 and bypass 215,the coolant enters an exit manifold 217 and exits the system at outlet220. Since the system 201 is a “once through” system it captures themaximum amount of heat that the system is releasing which is importantfor several reasons. First, because it is a single system, the system issimple to install. Second, if the heat is desired to be input intoanother process, like the bottoming cycle of a combined cycle powerplant, then the maximum heat is being captured which will result in thebest efficiency.

Another aspect of the present invention relates to a power augmentationand exhaust cooling system. FIG. 12 shows a combined power augmentationsystem and exhaust tempering system 300. When maximum power is desiredfrom the GT 1, the power augmentation system discussed above is used.When minimum power is desired, instead of the cooled air 117 exiting theintercooled compressor 116 and being routed to the gas turbine 1, thecompressed air is routed to a manifold 304 in the exhaust and is used toreduce the temperature of the GT exhaust 22 to a lower temperatureexhaust 322. The manifold 304 can be located inside or outside the heatrecovery steam generator 305. When exhaust tempering is desired, a valve302 positioned downstream of the first stage of the intercooledcompressor 116 closes and a tempering valve 301 opens. This allows air,after being compressed by the first stage of compressor 116 to exit theintercooled compressor 205. This air is generated using about 30% of thefuel that the current tempering air uses, thus significant part loadefficiency can be realized. Cool air then passes through a pipe 303 tothe manifold 304. When cool air is no longer needed, the above-describedprocess reverses.

Another aspect of the invention relates to a water recovery system fromthe condensate that is generated in the intercooling process. Referringto FIG. 13, a water recovery and steam injection system 400 inaccordance with an embodiment of the present invention is disclosed. Asthe air from compressor 116 is cooled in the compressor intercooler 205,water condenses and the pressure in the intercooler 205 forces the water401 out of a drain in the intercooler 205. The water 401 is collectedand pressurized by a pump 402. After the pump 402, the high pressurewater 401 goes through a secondary recuperator 404 where the warmexhaust 153 from the recuperator 171 increases the temperature of thewater 401 in the secondary recuperator 404 and turns the water 401 intosteam 406. The steam 406 is then injected into the compressed air thatis going to the main TPM recuperater 171 and then injected into thecompressor discharge plenum 14. The exhaust temperature is reduced intemperature and then exits the secondary recuperator 404 at exit 405.

If additional steam injection is desired, a secondary water source 407can be similarly pumped into the system 400 by a pump 408 and then sentto the secondary recuperator 404 for heating. Additionally, the inletair 115 to the supplemental compressor 116 can be intentionally takenfrom a source of air that has a higher humidity level than ambient airin order to produce more water for reclamation or steam injectionpurposes. For example, a very common cooling system for a gas turbineenergy system is an open cooling tower, where the cooling water isexposed to atmosphere intentionally to promote evaporation whichproduces cooler cooling water. This evaporation results in a locallyhigher than ambient humidity and if the supplemental compressor air wastaken at this source, more water would be produced in the intercoolerscompared to if the air was taken from ambient. By doing this, the powerplant can recover otherwise lost water. This water can be used in theTPM as described above or routed back to the plant water make up system.

In an alternate embodiment of the present invention, the water 401generated by the condensation in the compressor intercooler 205 can becaptured and used for other purposes. The water 401 is a result ofcondensation from the ambient air and therefore is potable drinkingwater. The water collected can be piped out of the power plant,collected and stored for future use, or used immediately within thepower plant. The water can also be piped to an adjacent facility such asin a typical cogeneration facility. In order to facilitate the alternateuse or collection of the water generated, a valve 410 is placed in thewater line 411, either before or after pump 402, such that the water 401can be selectively diverted prior to passing through the secondaryrecuperator 404 used to generate the steam. The water 401 can then becollected in a storage tank 412 or piped away from the power plant (notshown).

Another aspect of the present invention relates to a combined continuousair injection system 710 coupled with an air storage system 706 and/or ahigh frequency power regulation device 701 like a battery or asuper-capacitor. FIG. 14 shows an air injection system 710 which uses afueled engine 151 to compress ambient air 115 via a supplementalcompressor 116 to produce compressed air 117 that is heated in therecuperator 171 prior to injection into the GT through an injectionvalve 142. The power augmentation level in the gas turbine is directlyproportional to the mass flow of air injected into the GT, typicallyabout 1 MW of power for every 2.5 lb/sec of air injected. For example, asystem with a 2 MW engine will produce about 12 lb/sec of air and willcause a 7FA combined cycle power plant to increase about 5 MW in power.

A storage system 706 for use in this embodiment of the present inventionis described above and is also shown in FIG. 14. The storage system 706stores pressurized air and can add the pressurized air to the airinjection system 710. In order to increase the power boost from thepower plant during times of high ramping or intermittent load demandsstorage system injection control valve 707 can be opened releasingpreviously-stored compressed air to combine with compressed air fromsystem 710. The air from the storage system 706 is pre-heated in asecond recuperator (not shown) that is part of the storage system 706using the warm exhaust outlet 153, resulting in relatively cool exhaust,approximately 250 F, being discharged to the atmosphere 711. The heatedair from the storage system 706 is mixed with the air 141 from system710 prior to injection into the GT 1 through the injection control valve142.

A further addition to the system 700 is a battery and transformer 701,which provides two functions. First, it serves as the power source 702for starting the air injection system 710 by energizing a starter motoron the fueled engine 151. Secondly, it provides a very high speedregulation capacity 704 to the grid node 703 which is tied to thegenerator output 705 from the GT 1. Each of these systems has acharacteristic response time. The GT 1 responds in minutes, the airinjection system 710 responds in about 30-60 seconds, the air storagesystem 706 responds in 1-30 seconds and the battery 701 responds ismilliseconds. By combining these three systems into one system 700 thatprovides multiple functions, a very economic and high value systemresults.

FIGS. 15A and 15B shows the typical load pattern for a gas turbineengine where there is an initial ramp up 615, then a relatively levelload with a noon peak 617, and then a secondary peak 618 in the evening.By having the present invention operating at a power plant, the nominaloutput of the power plant can be increased 10 to 20% while providing thesame capacity to increase capability, as shown by FIG. 15B as comparedto FIG. 9B. This allows the plant to operate about 1% more efficientlyduring the off-peak times, as shown by 601, 58% in FIG. 15B versus 57%in FIG. 9B. With the storage system 706 available at the same powerplant, the ramp rate of the power plant, depicted as 605, can be matchedto the ramp rate of the load, depicted as 615 by selectively releasingair from the storage system 706. In addition, the air from the storagesystem 706 can be used to cover the extreme peaks experienced duringmid-day 617 and the evening 618. The quantity of air in the storagesystem 706 can be monitored and reserves can be made which could allowother peaking GT plants to start while the air from the storage systemis consumed. For example, during the noon peak, depicted as 617 in FIG.15A, a 50 MW simple cycle peaker, which takes 15 minutes to start, mighttypically be running at some minimal load to provide the spinningreserve necessary, so there is a combined cycle plant operating at 25 MWbelow base load and a peaker at 25 MW part load, just to have the 50 MWspinning reserve. With the storage system applied to the GT, the peakerunit could be shut off and the combined cycle at base load, with 15minutes of reserve air in the storage system to assure enough time tostart the peaker unit if higher loads are actually required. This wouldresult in an efficiency improvement to the grid. When the battery system701 of FIG. 14 is added to the present invention further gridefficiencies can be realized. The high frequency regulation capability,depicted as 607, is proven to reduce the actual amount of regulationrequired on the grid to maintain frequency control, so with the threesystems integrated together, fewer power plants will have to be on lineto provide the same level of frequency regulation. The present inventioncan be tailored in size to meet a specific grid requirement and can becombined or operated separately depending on the grid requirements.

While the invention has been described in what is known as presently thepreferred embodiment, it is to be understood that the invention is notto be limited to the disclosed embodiment but, on the contrary, isintended to cover various modifications and equivalent arrangementswithin the scope of the following claims. The present invention has beendescribed in relation to particular embodiments, which are intended inall respects to be illustrative rather than restrictive.

From the foregoing, it will be seen that this invention is one welladapted to attain all the ends and objects set forth above, togetherwith other advantages which are obvious and inherent to the system andmethod. It will be understood that certain features and sub-combinationsare of utility and may be employed without reference to other featuresand sub-combinations. This is contemplated by and within the scope ofthe claims.

The invention claimed is:
 1. A method of operating a gas turbine enginehaving power augmentation and exhaust gas tempering capabilitycomprising: operating a gas turbine engine comprising a compressor, acompressor discharge case, at least one combustor, and a turbine,fluidly connected to each other; pressurizing air using a supplementalcompressor which is driven by a fueled engine; and bypassing a finalstage of the supplemental compressor and directing a portion of an airsupply from a non-final stage of the supplemental compressor to anexhaust region of the gas turbine engine when reduced power from the gasturbine engine is desired so as to reduce exhaust temperature from thegas turbine engine; and directing air from the final stage to thecompressor discharge case for injection into the gas turbine engineupstream of the one or more combustors so as to increase power from thegas turbine engine.
 2. The method of claim 1, wherein the non-finalstage is a first stage.
 3. The method of claim 1, wherein thesupplemental compressor has cooling between each stage.
 4. The method ofclaim 1 further comprising closing a valve adjacent the non-final stage.5. The method of claim 4 further comprising opening a tempering valve todirect the air out of an intercooler and towards the exhaust region. 6.The method of claim 1, wherein the exhaust region has a manifold fordistributing the air from the supplemental compressor.
 7. A poweraugmentation and exhaust cooling system for a gas turbine enginecomprising: a supplemental compressor coupled to a fueled engine; afirst conduit fluidly connecting a non-final stage of the supplementalcompressor to an exhaust region of the gas turbine engine; a secondconduit fluidly connecting a final stage of the supplemental compressorto a compressor discharge case of the gas turbine engine; one or morevalves regulating flow between the supplemental compressor and theexhaust region; wherein air flowing through the first conduit bypassesthe final stage.
 8. The method of claim 7, wherein the non-final stageis a first stage.
 9. The system of claim 7, wherein the one or morevalves comprises a tempering valve for regulating flow of air from thenon-final stage of the supplemental compressor and to the exhaustregion.
 10. The system of claim 9 further comprising a valve forregulating flow to subsequent stages of the supplemental compressor. 11.The system of claim 7, wherein air from the non-final stage is routed toa manifold proximate the exhaust region to improve part load efficiency.12. The system of claim 7, wherein air flow from the supplementalcompressor to the compressor discharge case provides for poweraugmentation to the gas turbine engine.
 13. The system of claim 7,wherein air flow to the exhaust region is utilized to cool a temperatureof combustion gases passing through the exhaust region of the gasturbine engine.
 14. A method of selectively operating a gas turbineengine in each of a power augmentation mode and an exhaust temperingmode, the gas turbine engine comprising a compressor fluidly coupled toa compressor discharge case, a combustor, and a turbine, the methodcomprising: locating a manifold in an exhaust region of the turbine;using a fueled engine to drive a supplemental compressor; thesupplemental compressor having at least a first stage, an inner stagedownstream from the first stage, and a last stage downstream from theinner stage; fluidly coupling the supplemental compressor to anintercooler; operating the gas turbine engine in the exhaust temperingmode by: closing a valve between the inner stage and the intercooler topreclude substantially all air compressed by the first stage and cooledby the intercooler from reaching the inner stage, and opening a gastempering valve between the intercooler and the manifold to route aircompressed by the first stage and cooled by the intercooler to themanifold; then operating the gas turbine engine in the poweraugmentation mode by opening the valve and closing the gas temperingvalve to route air compressed by each of the first, the inner, and thelast stage and cooled by the intercooler to the compressor dischargecase.
 15. The method of claim 14, wherein the inner stage is adjacentthe first stage.
 16. The method of claim 14, wherein the manifold islocated inside a heat recovery steam generator.
 17. A method ofoperating a gas turbine engine having power augmentation and exhaust gastempering capability comprising: operating a gas turbine enginecomprising a compressor, a compressor discharge case, at least onecombustor, and a turbine, fluidly connected to each other; pressurizingair using a supplemental compressor which is driven by a fueled engine,the supplemental compressor having a downstream stage and an upstreamstage, the downstream stage being downstream of the upstream stage;bypassing the downstream stage and directing a portion of an air supplyfrom the upstream stage of the supplemental compressor to an exhaustregion of the gas turbine engine when reduced power from the gas turbineengine is desired so as to reduce exhaust temperature from the gasturbine engine; and directing air compressed by each of the upstreamstage and the downstream stage to the compressor discharge case forinjection into the gas turbine engine upstream of the one or morecombustors so as to increase power from the gas turbine engine.